Embodiments of the invention relate to a method for determining the composition of a fluid mixture in a well bore and more particularly, to a method for improving the determination of the composition of a flowing fluid mixture along a length of a well bore.
The oil and gas industry is very dependent on well bore measuring techniques to provide information about what is actually happening deep in a well bore. Many surveys are done before oil or gas is produced, including seismic and rock porosity, water content and micro seismic. However, there are few methods of obtaining data which gives a broad measurement of the behaviour of the well over its whole length, especially while the well is being produced.
Point pressure and temperature sensors have been in commonplace use since the 1940's and production logging tools are also now customarily used. It is quite common in the oil and gas industry to run logging tools which measure water cut and well bore resistivity, and also optical distributed temperature sensing systems into oil wells to measure the temperature profile over the complete length of the well bore.
The point sensors only provide indications of what is happening at the position of the sensor. Logging tools measure the complete well bore, but not in real time and they can only be run periodically. Logging tools are also difficult to run, when there are pumps in the well bore. Distributed temperature measurement is limited by the fact that, while the temperature profile can be interpreted to give information about other behaviour in the well bore, the temperature information in its raw state is not immediately useful in terms of determining the type of fluid produced (or injected).
The oil and gas industry is under pressure to achieve greater efficiency and increase production rates, all of which requires more understanding of reservoir storage and production behaviour. This has created a need for more two dimensional and three dimensional measurements of reservoir behaviour.